Drilling apparatus and system for drilling wells

ABSTRACT

A device for boring a well is provided, the device being attached to a motor having a power shaft for imparting rotational movement responsive to a fluid flow. The device includes a driver operatively connected to the power shaft, the driver having a tubular body with an internal bore for accommodating fluid flow, a first bit connected to the driver at a first end so that rotational movement of the driver is imparted to the first bit, and an inner bore. A second bit is attached to housing about the first bit. A nozzle communicating the internal portion of the tubular body with an outer portion thereof, the nozzle being oriented to deliver a portion of the fluid flow to the second bit.

CROSS REFERENCE TO RELATED APPLICATIONS

The present application is a continuation application, claiming priority to the U.S. patent application having Ser. No. 11/904,136, filed Sep. 26, 2007, which claims priority to the U.S. patent application having Ser. No. 11/713,942, filed Mar. 5, 2007, now U.S. Pat. No. 7,607,496. The present application also claims priority to the U.S. patent application having Ser. No. 12/584,100, filed Aug. 31, 2009. The above-referenced patents and patent applications are incorporated herein by reference, in their entirety.

BACKGROUND OF THE INVENTION

Conventionally, in the search for oil and gas, operators have utilized a specifically designed drill string to drill wells, the drill string being attached to a drill bit. To drill the well, the drill string is rotated, which in turn causes the bit to rotate, forming a hole in the earth, thus drilling the well. Various types of drill strings have been developed to drill directional, or inclined, well bores.

Different types of bottom hole assemblies have also been developed to drill wells. A typical drilling string for use drilling directional well bores may contain a bottom hole assembly having a bit, a bent sub, a drilling motor, and one or more measurement-while-drilling surveying and logging tools. When using a conventional bottom hole assembly, the drill string ideally is retained in a stationary orientation with respect to down hole rotation. The drilling motor generates rotation of the bit via circulation of the drilling fluid through the drilling motor, as known in the art. With the drill string retained in a stationary orientation with respect to the rotation, the well is drilled in the desired, controlled direction of the bend in the bent sub.

A common problem when using this type of drilling assembly is the torque generated by the bit. The torque from the bit generates an equal and opposite reactive torque that is transferred from the motor into the bottom hole assembly and drill string, causing counter-rotation relative to the bit. Further, the reactive torque, and hence the drill sting counter-rotation, can vary due to drilling conditions, such as the weight applied to the bit, properties of the rock being drilled, and the hole condition, which all vary independently of each other. As the bent sub is part of the bottom hole assembly being counter-rotated, the direction in which the well is being drilled changes responsive to changes in the reactive torque.

As a result, the directional driller is required to make numerous surface adjustments of the drill string, and hence the bent sub, to maintain drilling in a desired direction. These numerous adjustments reduce the efficiency of the drilling operation and require substantial time and cost. By eliminating, or greatly reducing, the reactive torque in the bottom hole assembly and drill string, drilling can proceed unabated in the desired direction, saving valuable rig time. Other benefits of eliminating, or reducing, reactive torque include the ability to use more powerful motors and more weight on bit to increase drilling rates, and the ability to drill a smoother, less tortuous borehole for running logging tools and setting casing. A non-reactive bit apparatus and method were disclosed in U.S. Pat. No. 5,845,721 entitled “Drilling Device And Method Of Drilling Wells”, which is incorporated herein by reference.

After a well is drilled, the well is prepared for running and cementing a casing string into the well. Hence, any time saved cleaning, running and cementing the casing can result in significant cost savings. Conventional tools have not allowed an operator to effectively drill with a casing string forming a part of the work string due to structural limitations of the casing string and the casing string thread connections. Generally, casing strings and casing string connections are not structurally designed to handle the stress and strain applied by the numerous torquing requirements for a drill string. Use of a non-reactive torque drilling device can enable drilling with an attached casing string.

Therefore, a need exists for a drilling device that will allow the drilling of a well with a casing string attached thereto, with the casing string able to be left within the well after cessation of drilling operations such that additional remedial operations, such as perforation of the casing, can be performed. There is also a need for a non-reactive drilling tool with dual bits.

SUMMARY OF THE INVENTION

Embodiments of the invention relate, generally, to devices for boring a well that include a motor with a power shaft for imparting rotational movement responsive to fluid flow. A driver can be operatively connected to the power shaft, the driver having a tubular body with an internal bore for accommodating the fluid flow. A first bit is attached to the driver such that rotational movement of the driver is imparted to the first bit. A second bit is attached to or otherwise formed on a housing disposed about the driver. A nozzle communicates fluid between the internal bore of the tubular body to an outer portion of the tubular body, the nozzle being oriented to deliver at least a portion of the fluid flow to the second bit. Directing of the fluid flow directly to the second bit can maximize the removal of cuttings. Additionally, the upward flow direction of the nozzles can provide a Venturi affect that reduces bottomhole pressure below the nozzles, which can improve hydraulic performance and drilling performance of the bits.

In an embodiment of the invention, the nozzles can be provided in a cross-over sub, or similar element, between the drive shaft and the first bit. In a further embodiment of the invention, a flow directing skirt can be provided to the cross-over sub and/or to the housing of the driver to direct fluid flow toward the second bit, the junk slot area, and into the annulus, which can further facilitate removal of cuttings generated by the first bit and cleaning of the second bit. In another further embodiment of the invention, the nozzles can include three or more nozzles angled in an upward direction, such as at an approximate 45 degree angle, oriented to provide fluid to the cutters of the second bit.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a perspective view of an embodiment of a drilling apparatus usable within the scope of the present disclosure.

FIGS. 2A, 2B and 2C depict a side cross-sectional view of the drilling apparatus of FIG. 1.

FIG. 3 depicts a cross-sectional view of the drilling apparatus of FIG. 2A taken from the line 3-3.

FIG. 4 depicts a cross-sectional view of the drilling apparatus of FIG. 2A taken from the line 4-4.

FIG. 5 is a schematic drawing of an embodiment of a drilling apparatus system of usable within the scope of the present disclosure disposed within a well.

FIG. 6 is a schematic drawing of the drilling apparatus system of FIG. 5 cemented within the well with perforations to a hydrocarbon reservoir.

FIG. 7 is a schematic drawing of the drilling apparatus system of FIG. 6 with the inner bit removed.

FIG. 8 is a schematic drawing of the drilling apparatus system of FIG. 5 drilling a well from a rig.

FIG. 9 is a cross-sectional view of an embodiment of a drilling apparatus usable within the scope of the present disclosure.

FIG. 10 is a disassembled perspective view of the drilling apparatus of FIG. 9.

FIG. 11 is a schematic drawing of the drilling apparatus of FIG. 9 disposed within a well.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS

Referring now to FIG. 1, a perspective view of an embodiment of a drilling apparatus 2 is shown. The drilling apparatus 2 includes a power shaft 4 having a first end with external threads 6 disposed thereon, and a second end with internal threads 8 disposed therein. A driver 10 can be threaded to the power shaft through use of complementary external threads 12 that will engage the internal threads 8 of the power shaft 4. The driver 10 also includes a second end having external threads 14. The depicted driver 10 has a cylindrical body having a plurality of cogs 16 and/or splines disposed thereon, proximate to a raised shoulder 18. A sleeve 20 is also shown, the sleeve having internal threads 22 on a first end for engagement with complementary external threads 14 of the driver 10, and a plurality of openings 24 at a second end. Also, on the radial end of the driver 10, a plurality of indentations 26 are shown.

FIG. 1 also depicts pinions 28, 30, 32, disposed through openings 24 of the driver 10 for rotation, through use of pins. For example, a pin 34 a is shown, which can be disposed through a corresponding pinion 32 and retained with bushings 36, 38. The pins can cooperate to engage with a radial shoulder located within the openings of the sleeve 20. FIG. 1 also illustrates a housing 40, which is shown having a first end 42 that will abut a ledge 44 of the sleeve 20. The depicted housing 40 also includes external threads 46 disposed on the opposing end.

FIG. 1 also depicts the thrust pack cylindrical assembly 48 which can include a plurality of ball bearings (not visible in FIG. 1), or other types of bearings or similar elements, as known in the art. The thrust pack assembly 48 can be disposed about the thrust mandrel 50. FIG. 1 depicts a thrust mandrel 50 with a first end having external threads 52 and a second end having a lip 54. A trim spacer 56 is also shown, the depicted trim spacer 56 being a ring member that cooperates with the thrust mandrel 50 and the thrust pack assembly 48, as shown in FIG. 2A. FIG. 1 also depicts an outer bit 58, having internal threads 60 at a first end, and a bit face 62 at a second end. The bit face 62 contains indentations for allowing fluid and debris circulation. A cross-over 64 is shown for facilitating assembly of the drilling apparatus 2, the cross-over 64 having a generally cylindrical body with internal threads 66 that will engage the external threads 14 of the driver 10. The cross-over 64 is also shown having internal threads 68, which engage external threads 72 of an inner bit 70. The opposing end of the inner bit 70 includes a cutting face 74, for boring of a well, as known in the art.

Referring now to FIGS. 2A, 2B and 2C, a cross-sectional view of the drilling apparatus 2 of FIG. 1 is shown. It should be noted that like numbers appearing in the various figures refer to like components. The outer bit 58 is shown disposed about the cross-over 64, with the inner bit 70 is threadably connected to the cross-over 64. The outer bit 58 is shown threadably connected to the housing 40 using the external threads 46 of the housing 40 and the internal threads 60 of the outer bit 58. The driver 10 is threadably connected to the cross-over 64 on one end, and to the power shaft 4 at the opposing end. The sleeve 20 is shown having a radial shoulder 80 within the previously described openings, wherein pins 34 a and 34 b are connected to the radial shoulders of the openings, such that the pins 34 a, 34 b are held in place as the pinions rotate, as described previously. Additionally, an indented bottom portion 82 of the sleeve 20 is shown, which includes the indentation 26 shown in FIG. 1. The indented bottom portion 82 is shown threadably attached to the thrust mandrel 50. The pins 34 a and 34 b are attached to the indented bottom portion 82 to fix the pins 34 a and 34 b in place during operation of the down hole motor.

The power shaft 4 is shown connected to a down hole motor 84, which can include a mud motor, such as a positive displacement motor available from Robbins and Meyers Inc. As seen in FIGS. 2A, 2B and 2C, the power shaft 4 is connected to the rotor 86 of the motor 84. The rotor 86 cooperates with a stator of the motor 84 and the fluid flow to impart a rotational movement to the power shaft 4, as understood by those of ordinary skill in the art. As seen specifically in FIG. 2C, the motor 84 is connected to a cross-over 88, and the cross-over 88 is connected to a casing string 90.

FIG. 3 depicts a cross-sectional view of the drilling apparatus 2 of FIG. 2A taken along the line 3-3. FIG. 3 shows the external cogs 16 of the driver 10. The pinion 32 is shown with the pin 34 a disposed therethrough; the pinion 30 is shown with the pin 34 b disposed there though; the pinion 91 is shown with the pin 34 c disposed there through; the pinion 92 is shown with the pin 34 d disposed there through; the pinion 94 is shown with the pin 34 e disposed there through; the pinion 96 is shown with the pin 34 f disposed there through. In operation, as the driver 10 rotates through connection to the rotor, the pinions 28, 30, 32, 91, 92, 94 and 96 rotate due to the engagement of the cogs, which in turn imparts a counter rotation movement to the housing 40 via the engagement of the pinion cogs with internal cogs 98 located on the housing 40.

Referring now to FIG. 4, a cross-sectional view of the drilling apparatus 2 of FIG. 2A is shown, taken along the line 4-4. In this view, the ends of pins 34 a, 34 b, 34 c, 34 d, 34 e, 34 f are shown configured to engage with the indented bottom portion 82 of sleeve 20, and in particular, with a slot within the indented bottom portion 82. A set screw or a similar fastener can be used to attach the pin ends to the indented bottom portion 82. Specifically, a set screw 102 is shown configured to be inserted into the slot 104, such that the end of pin 34 a is engaged with the set screw 102 so that the pin 34 a is attached to the indented bottom portion 82. The other set screws 106, 108, 110, 112, 114 can be similarly engaged with the respective pin ends of the other pins.

Referring now to FIG. 5, a schematic drawing of an embodiment of a drilling apparatus system disposed within a well 120 is shown. A down hole motor 84 is threadably attached to a cross-over sub 88, as described previously. Fluid flow through the inner bore of the casing string 90, and into the down hole motor 84, through the rotor-stator of the motor 84, causes rotation of the inner bit 70 in a first direction, which in turn will impart a counter rotational movement to the outer bit 58, such that the of the two bits in counter directions will produce a non-reactive force. FIG. 5 depicts the bits 70, 58 boring through subterranean reservoirs with the casing string 90 attached. Thus, the described non-reactive force facilitates the drilling of the well 120 with the attached casing string 90, which heretofore has not been possible due to the extreme torque applied to the casing string thread connections during conventional drilling operations.

Under many circumstances, a well is drilled in a series of sections, which are provided with progressively smaller hole sizes. Casings are run to consolidate the current progress, to protect some zones from contamination and to provide the well with the ability to hold higher pressures. FIG. 6 is a schematic drawing of an embodiment of a drilling apparatus system cemented within a well 120 with perforations 122 to a hydrocarbon reservoir 124. The cement, denoted by the numeral 126, can be applied to the annulus between the outer portion of the drilling apparatus 2 and casing 90 and the inner portion of the well 120 using various known techniques.

Referring now to FIG. 7, a schematic drawing of the drilling apparatus system of FIG. 6 is shown, with the inner bit 70 removed. FIG. 7 depicts the casing string 90 cemented in place. Once the casing string 90 is cemented, a second drilling apparatus system can be run into the hole, down the casing string 90 and through the open end so that drilling may continue. This second drilling apparatus system can also utilize a casing string as the work string. FIG. 8 depicts a schematic drawing of the drilling apparatus 2 drilling a well 127 from a rig 128. The rig is showed positioned on a drilling platform 130, located in water. FIG. 8 shows an intermediate casing string 132 within the well 127, while a second casing string 134 is used as a work string during drilling. The second casing string 134 can subsequently cemented in place after drilling a second portion of the well 127, as described previously. It should be noted that in various embodiments of the invention, a coiled tubing string or other types of tubular conductors can be used as the work string in place of the casing string. Due to the continuous nature of a coiled tubing string, use of a non-reactive torque system herein disclosed, allows use of coiled tubing as a work string.

Referring now to FIG. 9, a cross-sectional view an embodiment of a drilling apparatus is shown. FIG. 9 depicts the driver 10 being threadably connected to the cross-over sub 64, and the cross-over sub 64 threadably connected to the inner bit 70. It should be noted that in an embodiment of the invention, the driver 10, cross-over sub 64, and/or inner bit 70 may be integrally formed as a single member. The housing 40 is shown threadably connected to the outer bit 58, however in an embodiment of the invention, the housing 40 and outer bit 58 can be an integral member. During operation, the inner bit 70 rotates in a first direction, and the outer bit 58 rotates in an opposite direction, as described previously. FIG. 9 depicts a first passage 140 and a second passage 142 extending through the drilling apparatus.

Disposed within the first passage is a first nozzle 144, and disposed within the second passage is a second nozzle 146. The nozzles 144, 146 are shown oriented relative to the axial center line 148, in an upward direction, such as an approximate forty-five (45) degree angle of inclination. In various embodiments of the invention, the angle of inclination can range from 30 degrees to 75 degrees in an upward direction. While FIG. 9 depicts two nozzles 144, 146, in an embodiment of the invention, three or more nozzles can be provided. The size of the nozzle may be selected based on the desired flow rate, as understood by those of ordinary skill in the art. FIG. 9 also depicts a flow skirt 150 disposed about the cross-over sub 64. The flow skirt 150 can include a ring member formed integrally on the outer portion of the cross-over sub 64. As shown, the flow skirt 150 has an angled surface 152 that extends to a radially flat surface 154. The flow skirt 150 directs drilling fluid flow toward the outer bit and the junk slot area, and into the annulus.

FIG. 10 depicts a disassembled perspective view of the drilling apparatus of FIG. 9. The cross-over sub 64 is shown along with the passages 140, 142 disposed therethrough, adjacent the nozzles 144, 146. A third nozzle 156 is also shown. The flow skirt 150 is depicted having the radially flat surface 154. As noted earlier, the inner bit 70 can be threadably connects with the cross-over sub 64, and the cross-over sub 64 can in turn be threadably connected to the driver 10 (not visible in FIG. 10).

Referring now to FIG. 11, a schematic drawing of the drilling apparatus system 2 of FIG. 9 is shown disposed within a well 127. The inner bit 70 is shown drilling a bore hole 158 using cutters on the bit face 74, while the outer bit 58 is shown boring a larger hole within the well 127. In use, drilling fluid is pumped down the drill string, as readily appreciated by those of ordinary skill in the art. A portion of the drilling fluid will exit nozzles within the inner bit 70 (nozzles in inner bit 70 not shown), with the fluid flow being represented by the flow arrows “A” through the annular area 160 about the inner bit 70. The flow “A” flows in a generally upward direction toward the surface. The remaining portion of the drilling fluid will exit the nozzles 144 and 146, shown within the cross-over sub 64, with the fluid flow exiting the nozzles 144 and 146 represented by the flow arrows “B” within the annular area 162 about the outer bit 58.

In an embodiment of the invention, the nozzles can be machined for threaded placement into the cross-over sub 64 to allow different sizes of nozzles to be used. The nozzles can be supplied with drilling fluid flow from inside the cross-over sub 64. Because the inner bit 70 is drilling only part of the bore hole, a larger quantity of drilling fluid is pumped through the drill string than the quantity is required to adequately clean the inner bit. The nozzles which provide flow “A” on the inner bit can be sized and positioned such that the inner bit will receive the required flow to be effectively cleaned during the drilling. The remainder of the flow (i.e. flow “B”) can ext from the nozzles exiting the cross-over sub 64.

In an embodiment of the invention, the flow skirt 150 can be provided as an integral part of the cross-over sub 64 that extends about the circumference of the cross-over sub 64. The flow skirt 150 can direct drilling fluid flow toward the cutters of the outer bit 58 and into the annulus 162. The flow being directed can be continuous flow from the inner bit and from the nozzles, while the continuous flow from the nozzle will strike the bit face intermittently due to the counter rotation. The flow skirt 150 can also prevent drilling fluid and cuttings from becoming lodged in the bearing area between the cross-over sub 64 and the outer bit 58. Additionally, the flow skirt 150 can be used as simply a deflector sleeve without the use of the nozzles, to deflect fluid flow from the bearing area.

In an embodiment of the invention, the upward direction of the nozzles can provide a Venturi effect that will reduce the bottom-hole pressure below the nozzles. The resulting reduction of bottom-hole pressure can improve both the hydraulic performance and drilling performance of the inner bit 70.

Changes and modifications in the specifically described embodiments can be carried out without departing from the scope of the invention which is intended to be limited only by the scope of the appended claims and any equivalents thereof. 

1. A device for boring a well, the device comprising: a driver comprising a first end and a second end, wherein the first end of the driver is operatively connected to a power shaft of a motor for receiving rotational force; a first bit attached to the second end of the driver; a second bit attached to the driver at a point between the first end and the second end; at least one fluid passage comprising a nozzle, wherein said at least one fluid passage communicates between an internal bore of the driver and an exterior of the driver, wherein said at least one fluid passage is disposed between the first bit and the second bit, and wherein said at least one fluid passage, the nozzle, or combinations thereof are angled toward the second bit such that fluid passing through the nozzle flows in an uphole direction to contact the second bit.
 2. The device of claim 1, further comprising at least one bearing assembly operatively disposed between the driver and a housing disposed about the driver for transferring axial and lateral loads generated during drilling.
 3. The device of claim 2, wherein said at least one bearing assembly comprises a thrust mandrel and a plurality of ball bearings operatively associated with the thrust mandrel.
 4. The device of claim 2, wherein said at least one bearing assembly comprises a first end and a second end, and wherein an end of the housing is rotatably associated with the first end of said at least one bearing assembly for facilitating rotation of the first bit and the second bit.
 5. The device of claim 1, wherein the first bit comprises a first set of cutter teeth positioned to drill a well in a first rotational direction, and wherein the second bit comprises a second set of cutter teeth positioned to drill the well in a counter rotational direction opposite the first rotational direction.
 6. The device of claim 1, wherein the first bit is offset relative to the second bit such that the first bit extends farther into a well relative to the second bit.
 7. The device of claim 1, further comprising a casing string disposed in communication with the driver, wherein the casing string is in fluid communication with the first bit.
 8. The device of claim 1, further comprising a flow skirt disposed between said at least one fluid passage and the second bit for further directing fluid flow to the second bit.
 9. The device of claim 8, wherein the flow skirt comprises a ring member having an angled surface that extends to a radially flat surface.
 10. A device for boring a well, the device comprising: a driver comprising a first end and a second end, wherein the first end of the driver is operatively connected to a power shaft of a motor for receiving rotational force; a first bit attached to the second end of the driver; a second bit attached to the driver at a point between the first end and the second end; at least one fluid passage comprising a nozzle, wherein said at least one fluid passage communicates between an internal bore of the driver and an exterior of the driver, and wherein said at least one fluid passage is disposed between the first bit and the second bit; and a flow skirt disposed between said at least one fluid passage and the second bit for directing fluid flow from said at least one fluid passage to the second bit.
 11. The device of claim 10, wherein the flow skirt comprises a ring member having an angled surface that extends to a radially flat surface.
 12. The device of claim 10, wherein said at least one fluid passage, the nozzle, or combinations thereof are angled toward the second bit such that fluid passing through the nozzle flows in an uphole direction to contact the second bit
 13. The device of claim 10, further comprising at least one bearing assembly operatively disposed between the driver and a housing disposed about the driver for transferring axial and lateral loads generated during drilling.
 14. The device of claim 13, wherein said at least one bearing assembly comprises a thrust mandrel and a plurality of ball bearings operatively associated with the thrust mandrel.
 15. The device of claim 13, wherein said at least one bearing assembly comprises a first end and a second end, and wherein an end of the housing is rotatably associated with the first end of said at least one bearing assembly for facilitating rotation of the first bit and the second bit.
 16. The device of claim 10, wherein the first bit comprises a first set of cutter teeth positioned to drill a well in a first rotational direction, and wherein the second bit comprises a second set of cutter teeth positioned to drill the well in a counter rotational direction opposite the first rotational direction.
 17. The device of claim 10, wherein the first bit is offset relative to the second bit such that the first bit extends farther into a well relative to the second bit.
 18. The device of claim 10, further comprising a casing string disposed in communication with the driver, wherein the casing string is in fluid communication with the first bit.
 19. A method for boring a well, the method comprising the steps of: rotating a first bit in a first direction to thereby cause the first bit to bore into a formation, wherein rotation of the first bit produces a first torque; rotating a second bit in a second direction opposite the first direction to cause the second bit to bore into the formation, wherein rotation of the second bit produces a second torque equal and opposite the first torque, thereby minimizing effects of the first torque; and flowing drilling fluid in an uphole direction to contact the second bit.
 20. The method of claim 19, wherein the step of rotating the first bit in the first direction comprises rotating a drive member of a motor in operative communication with the first bit.
 21. The method of claim 20, wherein the step of rotating the second bit in the second direction comprises transferring rotational force from the drive member to at least one associated gear or pinion to change the direction of the rotational force, and transferring the rotational force from said at least one associated gear or pinion to the second bit.
 22. The method of claim 20, wherein the step of flowing drilling fluid in the uphole direction to contact the second bit comprises providing the drilling fluid through at least one fluid passage disposed between the first bit and the second bit, wherein said at least one fluid passage is angled in the uphole direction.
 23. The method of claim 20, wherein the step of flowing drilling fluid in the uphole direction to contact the second bit comprises contacting the drilling fluid with a flow skirt disposed between the first bit and the second bit, wherein the flow skirt comprises an angled surface for directing the drilling fluid to the second bit. 